Compositions and methods for treatment of well bore tar

ABSTRACT

Of the many compositions and methods provided herein, one method includes a method comprising: contacting tar resident in a well bore with a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene-acrylate polymer, and any combination thereof; and allowing the tar stabilizing polymer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 12/630,502, entitled “Compositions and Methods forTreatment of Well Bore Tar,” filed on Dec. 3, 2009, which is adivisional of U.S. patent application Ser. No. 11/873,257, entitled“Compositions and Methods for Treatment of Well Bore Tar,” filed on Oct.16, 2007, now U.S. Pat. No. 7,665,523, the entire disclosures of whichare incorporated herein by reference.

BACKGROUND

The present invention relates to methods and compositions for use insubterranean operations. More particularly, the present inventionrelates to tar stabilizing polymers used to treat tar resident in a wellbore and associated methods of use.

Many subterranean operations involve the drilling of a well bore fromthe surface through rock and/or soil to penetrate a subterraneanformation containing fluids that are desirable for production. In thecourse of drilling operations and other subterranean operations, thedrillstring and/or other equipment may come into contact with zones ofrock and/or soil containing tar (e.g., heavy hydrocarbons, asphalt, andbitumens); in many such operations, it may be desirable to drill thewell bore through these tar-containing zones. However, tar is arelatively tacky substance that may readily adhere to any surface thatit contacts, including the surfaces of the well bore and/or anyequipment utilized during the drilling operation. Tar also may dissolveinto many synthetic treatment fluids used in the course of drillingoperations, increasing the tacky and adhesive properties of the tar. Ifa sufficient amount of tar adheres to surfaces in the well bore ordrilling equipment, it may, among other problems, prevent thedrillstring from rotating, prevent fluid circulation, or otherwiseimpede the effectiveness of a drilling operation. In some cases, it maybecome necessary to remove and/or disassemble the drillstring in orderto remove accretions of tar, a process which may create numerous costand safety concerns. The accretion of tar on drilling equipment and/orin the well bore also can impede any subsequent operations downhole,including cementing, acidizing, fracturing, sand control, and remedialtreatments. In addition, soft, tacky tar that manages to reach thesurface may foul surface equipment, including solids screeningequipment.

Existing methods of managing these problems that result from well boretar incursion may be problematic. Some of these methods involveeffecting an increase in hydrostatic pressure in the well bore so as toforce the tar out of the well bore to the surface. However, thisincreased hydrostatic pressure may damage the well bore and/or a portionof the subterranean formation. Other conventional methods utilizetreatment fluids that comprise dispersants, surfactants, and/orsolubilizers, which allow the tar particles to dissolve in or homogenizewith the treatment fluids. However, the tar particles may not be readilyseparated out of the fluid once they have dissolved into or homogenizedwith the fluid. The presence of the tar particles in the treatment fluidmay alter its rheological properties and/or suspension capacity, whichmay limit its use in subsequent operations. Moreover, the addition ofthese dispersants, surfactants, and solubilizers may increase thecomplexity and cost of the drilling operation.

SUMMARY

The present invention relates to methods and compositions for use insubterranean operations. More particularly, the present inventionrelates to tar stabilizing polymers used to treat tar resident in a wellbore and associated methods of use.

An embodiment of the present invention provides a method for treatmentof well bore tar. The method may comprise contacting tar resident in awell bore with a tar stabilizing polymer comprising at least one polymerselected from the group consisting of a styrene polymer, an acrylatepolymer, a styrene-acrylate polymer, and any combination thereof. Themethod may further comprise allowing the tar stabilizing polymer tointeract with the tar to at least partially reduce the tendency of thetar to adhere to a surface.

Another embodiment of the present invention provides a method fortreatment of well bore tar. The method may comprise using a drill bit toenlarge a well bore in a subterranean formation comprising tar. Themethod may further comprise circulating a drilling fluid past the drillbit to remove cuttings from the drill bit, wherein the drilling fluidcomprises an aqueous fluid and a tar stabilizing polymer comprising atleast one polymer selected from the group consisting of a styrenepolymer, an acrylate polymer, a styrene-acrylate polymer, and anycombination thereof.

Yet another embodiment of the present invention provides a treatmentfluid. The treatment fluid may comprise an aqueous fluid. The treatmentfluid may further comprise a tar stabilizing polymer comprising at leastone polymer selected from the group consisting of a styrene polymer, anacrylate polymer, a styrene-acrylate polymer, and any combinationthereof.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to methods and compositions for use insubterranean operations. More particularly, the present inventionrelates to tar stabilizing polymers used to treat tar resident in a wellbore and associated methods of use. As used herein, the term “tarstabilizing polymer” refers to a polymer that can interact with tarresident in a well bore such that the tar becomes less tacky and/or lessable to adhere to a surface. One of the many advantages of the presentinvention, many of which are not discussed or alluded to herein, is thattar treated by the compositions and methods disclosed herein may besubstantially less tacky and/or less able to adhere to a surface. As aresult, tar treated in this manner may be susceptible to screenseparation from treatment fluids, drill cuttings, tar sands, and thelike.

Embodiments of the present invention disclose tar stabilizing polymerscomprising a styrene polymer, an acrylate polymer, a styrene-acrylatepolymer, or any combination thereof. The suitable tar stabilizingpolymers generally can be emulsified in an aqueous fluid in accordancewith present embodiments. In some embodiments, the tar stabilizingpolymers may be ionic or nonionic in nature. In certain embodiments, thetar stabilizing polymers may interact with the tar resident in a wellbore such that the properties of the tar are altered. In certainembodiments, the tar stabilizing polymers may bind or coat the tar suchthat the tar becomes less sticky.

Examples of styrene polymers that may be suitable for use in embodimentsof the present invention include, but are not limited to, styrenecopolymers which include co-monomers of styrene or any derivativethereof. In some embodiments, the styrene polymer may be made bypolymerizing styrene, which may be substituted or unsubstituted. Thestyrene may be substituted with any number of different groups that willbe evident to those of ordinary skill in the art, including withoutlimitation chloro groups, bromo groups, fluoro groups, alkyl groups,alkoxy groups, alkenyl groups, alkynyl groups, aryl groups, andsubstituted versions thereof. Combinations of styrene polymers may alsobe suitable, in certain embodiments. In some embodiments, the styrenepolymer may comprise styrene in an amount in a range of about 90% toabout 100% by weight of the styrene polymer, about 95% to about 100% byweight of the styrene polymer, or about 99% to about 100% by weight ofthe styrene polymer. In one embodiment, the styrene polymer may consistof styrene. In some embodiments, the styrene polymer may be essentiallyfree of acrylate and/or acrylic acid.

Examples of acrylate polymers that may be suitable for use inembodiments of the present invention include, but are not limited to,acrylate copolymers which include co-monomers of acrylate or anyderivative thereof. The acrylate may be substituted with any number ofdifferent groups that will be evident to those of ordinary skill in theart, including without limitation chloro groups, bromo groups, fluorogroups, alkyl groups, alkoxy groups, alkenyl groups, alkynyl groups,aryl groups, and substituted versions thereof. In accordance withpresent embodiments, the acrylate may comprise two or more unitsindividually selected from the group consisting of -acrylate,-methacrylate, -ethylacrylate, -propylacrylate, -butylacrylate,-tert-butyl-acrylate, -n-hydroxyethyl methacrylate, -potassium acrylate,-pentabromobenzyl acrylate, -methyl methacrylate, -ethyl methacrylate,-n-nitrophenyl acrylate, -methyl 2-(acyloxymethyl)acrylate, -cyclohexylacrylate, -n-ethylhexyl acrylate, any derivative thereof. Combinationsof acrylate polymers may also be suitable, in certain embodiments. Insome embodiments, the acrylate polymer may be formed by polymerizingacrylic acid, which may be subsequently neutralized to form the acrylatecopolymer. In some embodiments, the acrylate polymer may compriseacrylate in an amount in a range of about 90% to about 100% by weight ofthe acrylate polymer, about 95% to about 100% by weight of the acrylatepolymer, or about 99% to about 100% by weight of the acrylate polymer.In one embodiment, the acrylate polymer may consist of acrylate. In someembodiments, the acrylate polymer may be essentially free of styrene.

Examples of styrene-acrylate polymers that may be suitable for use inembodiments of the present invention may include, but are not limitedto, styrene-acrylate copolymers and mixed copolymers which include atleast one unit comprising styrene, a substituted styrene, and anyderivative thereof; and at least one comprising -acrylate,-methacrylate, -ethylacrylate, -propylacrylate, -butylacrylate,-tert-butyl-acrylate, -n-hydroxyethyl methacrylate, -potassium acrylate,-pentabromobenzyl acrylate, -methyl methacrylate, -ethyl methacrylate,-n-nitrophenyl acrylate, -methyl 2-(acyloxymethyl)acrylate, -cyclohexylacrylate, -n-ethylhexyl acrylate, or any derivative thereof.Combinations of suitable styrene-acrylate polymers may also be suitable,in certain embodiments.

In some embodiments, the tar stabilizing polymers may be provided in theform of a latex emulsion or a powder. For example, a latex emulsion maybe used that comprises the tar stabilizing polymer. In some embodiments,the latex emulsion may be in the range from about 5% to about 60% activeby weight. In some embodiments, the latex emulsion may have a pH in therange of about 2 to about 4. The latex emulsion may further comprise asurfactant. Generally, any surfactant that will emulsify and/or suspendthe tar stabilizing polymers may be used in embodiments of the fluids ofthe present invention. In certain embodiments, it may be desirable toselect a surfactant that will not emulsify the tar sought to be treated.In certain embodiments, the surfactants may be present in an amountsufficient to emulsify and/or suspend the tar stabilizing polymers. Thisamount may depend on, among other things, the type of surfactant usedand the amount of tar stabilizing polymer to be emulsified and/orsuspended. A person of ordinary skill in the art will recognize, withthe benefit of this disclosure, the type and amount of surfactant thatshould be added for a particular application. In another embodiment, thetar stabilizing polymers may be provided in the form of a powder thatcan, for example, be dispersed in water. In some embodiments, the tarstabilizing polymer may have, for example, a particle size of less thanabout 1 micron, less than about 500 nanometers, or less than about 100nanometers.

In accordance with present embodiments, one or more of the tarstabilizing polymers may be included in a treatment fluid as describedherein. As used herein, the term “treatment fluid” refers to any fluidthat may be used in a subterranean application in conjunction with adesired function and/or for a desired purpose. The term “treatmentfluid” does not imply any particular action by the fluid or anycomponent thereof. Treatment fluids may be used, for example, to drill,complete, work over, fracture, repair, or in any way prepare a well borefor recovery of materials residing in a subterranean formationpenetrated by the well bore. Examples of treatment fluids include, butare not limited, cement compositions, drilling fluids, spacer fluids,and spotting fluids.

In some embodiments, at least one tar stabilizing polymer may beincluded in a treatment fluid in a quantity sufficient to treat the tarin the well bore. In certain embodiments, the concentration of the tarstabilizing polymer in the treatment fluid may be at least about 1% byvolume of the fluid, and up to an amount such that the tar stabilizingpolymer will precipitate out of the fluid. In certain embodiments, theconcentration of tar stabilizing polymer in the treatment fluid may bein the range of from about 1% to about 70% by volume of the fluid. Incertain embodiments, the concentration of tar stabilizing polymer in thetreatment fluid may be in the range for from about 1% to about 10% byvolume of the fluid. In certain embodiments, the tar stabilizing polymermay be added to the treatment fluid in the form of a latex-type emulsionor as dispersed particles. One of ordinary skill in the art, with thebenefit of this disclosure, will be able to determine the appropriateconcentration of the tar stabilizing polymer in the fluid for aparticular application.

In some embodiments, the treatment fluid may further comprise an aqueousfluid. For example, the tar stabilizing polymer may be dispersed in theaqueous fluid to form the treatment fluid. In one embodiment, a latexemulsion comprising a tar stabilizing polymer may be dispersed in theaqueous fluid. In another embodiment, a powder comprising a tarstabilizing polymer may be dispersed in the aqueous fluid. The aqueousfluid utilized in the treatment fluids of the present invention may befresh water, distilled water, or salt water (e.g., water containing oneor more salts dissolved therein). In certain embodiments, the treatmentfluid may be an aqueous-based fluid. Generally, the water can be fromany source, provided that it does not contain compounds that undesirablyaffect other components of the treatment fluid.

In certain embodiments, the treatment fluids of the present inventionmay further comprise a viscosifier, for example, to aid in suspendingthe tar stabilizing polymer in the treatment fluid. Suitableviscosifying agents may include, but are not limited to, colloidalagents (e.g., clays such as bentonite, polymers, and guar gum),emulsion-forming agents, diatomaceous earth, biopolymers, syntheticpolymers, chitosans, starches, gelatins, or mixtures thereof.

Other additives suitable for use in subterranean treatment fluids mayalso be added to embodiments of the treatment fluids. The treatmentfluids of the present invention may comprise any such additionaladditives that do not undesirably interact with the tar stabilizingpolymer or other components of the fluid. The treatment fluids used inmethods of the present invention optionally may comprise any number ofadditional additives, including, but not limited to, salts, surfactants,fluid-loss-control additives, gases (e.g., nitrogen, carbon dioxide)surface-modifying agents, tackifying agents, foamers, corrosioninhibitors, scale inhibitors, catalysts, clay-control agents, biocides,friction reducers, antifoam agents, bridging agents, dispersants,flocculants, hydrogen sulfide scavengers, carbon dioxide scavengers,oxygen scavengers, lubricants, breakers, weighting agents (e.g.,barite), relative-permeability modifiers, resins, particulate materials(e.g., proppant particulates), wetting agents, coating-enhancementagents, and the like. Weighting agents may be used, for example, intreatment fluids, such as, drilling fluids to provide a densitysufficient to, for example, control formation pressures. One of ordinaryskill in the art, with the benefit of this disclosure, will be able todetermine which additional additives are appropriate for a particularapplication.

As will be appreciated by those of ordinary skill in the art, with thebenefit of this disclosure, embodiments of the treatment fluids may beused in a variety of subterranean operations for treatment of tarresident in a well bore. By treatment of the tar with a tar stabilizingpolymer, as described herein, the adhesiveness of the tar may bereduced, thus facilitating removal of the tar from a well bore or othersurface, for example. In some embodiments, the present inventiondiscloses a method comprising contacting tar resident in a well borewith a tar stabilizing polymer, and allowing the tar stabilizing polymerto interact with the tar to at least partially reduce the tendency ofthe tar to adhere to a surface. In this manner, the removal of the tarfrom the well bore or other surface may be facilitated. In oneembodiment, a treatment fluid comprising the tar stabilizing polymer maybe introduced into the well bore such that the tar stabilizing polymercontacts the tar. One of ordinary skill in the art, with the benefit ofthis disclosure, should be able to determine the appropriate amount oftime to allow the tar stabilizing polymer to interact with the tar so asto at least partially reduce the adhesiveness of the tar. In certainembodiments, after the tar stabilizing polymer has been allowed tointeract with the tar, the tar then may be removed from the well bore byany means practicable for the given application.

In some embodiments, a treatment fluid comprising a tar stabilizingpolymer may be introduced into a well bore as a drilling fluid. Forexample, a drill bit may be used to enlarge the well bore, and thetreatment fluid comprising the tar stabilizing polymer may be circulatedin the well bore past the drill bit. In some embodiments, the drillingfluid may be passed down through the inside of a drill string, exitingat a distal end thereof (e.g., through the drill bit), and returned tothe surface through an annulus between the drill string and a well borewall. Among other things the circulating drilling fluid should lubricatethe drill bit, carry drill cuttings to the surface, and/or balanceformation pressure exerted on the well bore. In certain embodiments, thedrilling fluid may have a density in the range of from about 7.5 poundsper gallon (“lb/gal”) to about 18 lb/gal, and alternatively from about12 lb/gal to about 18 lb/gal.

In some embodiments, tar may be encountered in the course of drillingthe well bore. The zones of the well bore may be intentionally orunintentionally contacted during the course of drilling. For example,embodiments may include drilling through zones of the well bore thatcontain tar sands. The term “tar sands” does not imply or require anyspecific amount of tar to be present. In some embodiments, one or moregenerally horizontal well bores may be drilled through the tar sands. Inaccordance with present embodiments, a tar stabilizing polymer may beincluded in the drilling fluid as the well bore is drilled in thesetar-containing zones. In this manner, the tar stabilizing polymercontained in the treatment fluid may modify at least a portion of tarsuch that is becomes less tacky, making it less likely to stick to drillstrings and other tubulars used in drilling operations. Tar modified inthis way may yield tar cuttings that can be removed more effectivelyfrom the well bore. Additionally, tar that is drilled through may beless likely to flow into the well bore or the subterranean formation asthe plastic properties of the tar may be altered. Similarly, the treatedtar that forms about the surface of the well bore may act to stabilizethe well bore. In addition, tar treated with the tar stabilizingpolymers may be separated from a treatment fluid by passing the fluidthrough a screen or similar separation apparatus.

In some embodiments, a treatment fluid comprising a tar stabilizingpolymer may be introduced into a well bore as a pill for spot treatment,wherein the treatment fluid is introduced into the well bore to interactwith tar in a specific portion of the well bore. In some embodiments,the pill may be introduced into a zone of the well bore that containstar sands. The pill should enter the well bore and interact with tarresident in the well bore, thus modifying at least a portion of the tarsuch that is become less tacky. In certain embodiments of this type, thetar stabilizing polymer may be allowed to interact with the tar residentin the well bore for at least a time sufficient to at least partiallyreduce the adhesiveness of the tar. In some embodiments, this may bemore than about one hour. In others, more time will be required to atleast partially reduce the adhesiveness of the tar, depending upon,among other factors, the temperature inside the well bore and the amountof tar in the portion of the well bore being treated. One of ordinaryskill in the art, with the benefit of this disclosure, will be able todetermine the appropriate amount of time to allow the tar stabilizingpolymer to interact with the tar. In certain embodiments, after the tarstabilizing polymer has been allowed to interact with the tar, the tarthen may be removed from the well bore by any means practicable for thegiven application. In some embodiments, the pill may be used ahead ofand/or behind a non-aqueous drilling fluid, which may comprise anynumber of organic liquids, including, but are not limited to, mineraloils, synthetic oils, esters, paraffin oils, diesel oil, and the like.

In some embodiments, the amount of the tar stabilizing polymer presentin the treatment fluid may be monitored while the tar stabilizingpolymer is circulated in the well bore. For example, once a unit of tarstabilizing polymer in a treatment fluid is allowed to interact with aunit of tar in a well bore, that unit of the tar stabilizing polymer maybe depleted from the treatment fluid and thus unable to interact withadditional tar. For this reason, it may be desirable to monitor theconcentration of the tar stabilizing polymer in the treatment fluid todetermine if more should be added. In some embodiments, the tarstabilizing polymer may be added to the treatment fluid before thetreatment fluid is introduced into the well bore, for example, abatch-mixing process. In some embodiments, it may be desirable tocontinue to add the tar stabilizing polymer to the treatment fluid(e.g., “on-the-fly” mixing) according to the monitored concentration ofthe tar stabilizing polymer in the treatment fluid. In some embodiments,the concentration of tar stabilizing polymer in the treatment fluid maybe monitored by direct measurement. In some embodiments, theconcentration of tar stabilizing polymer in the treatment fluid may bemonitored indirectly by measuring the depletion of the tar stabilizingpolymer from the treatment fluid. The concentration of the tarstabilizing polymer in the treatment fluid may be monitored, forexample, by analytical polymer spectroscopy, chromatography, gravimetry,and quantitative precipitation.

To facilitate a better understanding of the present invention, thefollowing examples of specific embodiments are given. In no way shouldthe following examples be read to limit or define the entire scope ofthe invention.

Example 1

An aqueous-base fluid was formulated as shown in Table 1.

TABLE 1 Base Fluid 1 Fresh Water (lb/bbl) 345.8 Xanthan Gum (lb/bbl)0.701 Starch (lb/bbl) 4.206 Cellulose (lb/bbl) 0.701 Caustic Soda(lb/bbl) 0.05

A nonaqueous-base fluid was also formulated as shown in Table 2.

TABLE 2 Base Fluid 2 Synthetic Base Oil (lb/bbl) 131.45 Fatty AcidEmulsifier (lb/bbl) 10 Freshwater (lb/bbl) 84.12 Lime (lb/bbl) 1Polymeric Filtration Agent (lb/bbl) 2 Barium Sulfate (lb/bbl) 188.96Calcium Carbonate (lb/bbl) 15 Calcium Chloride (lb/bbl) 29.09 SimulatedDrill Solids (lb/bbl) 20 Rheology Modifier (lb/bbl) 1

A 50 g sample of tar sand (25% tar by mass) was placed in a first ½ labbarrel along with 133.1 g of Base Fluid 1 and a steel test rod. A 12.5 gsample of tar was placed in a second ½ lab barrel along with 216.9 g ofBase Fluid 2 and a steel test rod. The barrels were then hot rolled for16 hours at 150° F. (approx. 66.7° C.) under 200 psi in a rolling cell,and the test rods were visually inspected for tar accretion. Base Fluid1 was contaminated with tar sand, and tar was accreted on the test rod.Base Fluid 2 was contaminated with tar, and tar was accreted on the testrod.

Example 2

The two fluid samples were prepared as set forth in Table 3 using BaseFluid 1 described in Table 1. The fluid samples are designated Sample Aand B in the table below. The styrene-acrylate polymers used in thisexample were obtained as an emulsion and used as received. Baracor 700™corrosion inhibitor is an anti-corrosion additive commercially availablefrom Halliburton Energy Services, Houston, Tex. After hot rolling for 16hours at 150° F. (approx. 66.7° C.) under 200 psi in a rolling cell, themass of the test rod was determined both with any accreted tar and afterthe accreted tar had been cleaned off. These masses and the mass of theaccreted tar for each sample is reported in Table 3.

TABLE 3 Sample A B Base Fluid 1 (g) 133.1 150.6 Styrene-Acrylate 15 15Emulsion (g) Baracor 700 ™ 0.75 0.75 Corrosion Inhibitor (ml) Tar Sand(g) 50 — Tar (g) — 12.5 Post Accretion 337.45 337.16 Test Rod Mass (g)Post Cleaning 337.25 336.93 Test Rod Mass (g) Mass of 0.20 0.23 accretedtar (g) Observations Tar not sticking to cell wall. Tar form smallflocs. Tar Rod is clean. Tar is firm, not on cell wall. Rod has notsticky. Sand is loosely adhered flocs that separated from tar and can beeasily brushed settled on bottom of cell. away. Tar is pliable Fluid notcontaminated. but not sticky.

Example 3

In this example, tar was screened from tar-containing fluids. Base fluid1 was combined with tar sand and, in two cases, a treatment additive, asillustrated in Table 4 below. The tar-containing fluids were hot rolledthen poured across a vibrating screen material to assess potentialscreen clogging properties. A screen may be considered fouled if the taris adhesive and begins to seal/clog the screen openings therebypreventing a fluid from effectively draining. Sample C was a baselinereference of nontreated, adhesive tar and yielded adhesive screenfouling. Sample D was an unsuccessful treatment with a sodium salt thatalso yielded adhesive screen fouling. Sample E was a chemical treatmentof tar with styrene-acrylate polymers that yielded a non-adhesive tarand minimized screen fouling. The styrene-acrylate polymers used in thisexample (E) were the same as in the previous tests.

TABLE 4 Sample C D E Base Fluid 1 (g) 149.8 149.8 149.8 Sodium Salt (g)— 26.25 — Styrene acrylate — — 15 emulsion (g) Baracor 700 ™ Corrosion —— 0.75 Inhibitor (ml) Tar Sand (g) 50 50 50

Example 4

In this example, another aqueous-base fluid was formulated as shown inTable 5. This aqueous-base fluid is referred to in Table 5 as Base Fluid3.

TABLE 5 Base Fluid 3 Fresh Water (bbl) 0.976 (341.8 ml) Xanthan Gum (lb)0.877 Starch (lb) 5.261 Caustic Soda (lb) 0.035 Bridging Agent (lb)8.768 Simulated Drill Solids (lb) 1.754

Fluid samples were prepared by adding a styrene copolymer to Base Fluid3 in different quantities to determine its effect on well bore tar, asset forth in Table 6 below. The fluid samples are designated Samples Fand G in the table below. The styrene copolymer was obtained as a latexemulsion (approx. 45 wt % active) and used as received. Baracor 700™corrosion inhibitor, available from Halliburton Energy Services, Inc.,was also added to the fluid samples, as indicated in the table below.Tar sands with approximately 80% sands and 20% bitumen by weight wereused for this test. A steel rod was used to mimic the drill stringsinteraction with the tar sands. For each test, the tar sands were placedin a lab barrel together with the respective fluid sample and the steelrod. The system was then aged by rolling at approximately 77° F.(approx. 25° C.) for 16 hours in a rolling cell. The mass of the steelrod was determined prior to testing without any accreted tar and aftertesting with accreted tar. The mass of the rod was also measured afterrinsing under a stream of water. These masses and the mass of theaccreted tar for each sample are reported in the table below.

TABLE 6 Sample F G Base Fluid 3 (ml) 120 120 Styrene Latex 10 30Emulsion (lb/bbl) Baracor 700 ™ 6 6 Corrosion Inhibitor (lb/bbl) TarSands (lb/bbl) 85 85 Pre-Accretion 338.53 340.40 Test Rod Mass (g)Post-Accretion 341.75 343.42 Rod Mass (g) (338.61 after rinsing) (341.47after rinsing) Mass of accreted 3.22 3.02 tar (g) (0.08 after rinsing)(1.07 after rinsing) Observations Some tar stuck to bar Some tar stuckto bar but but came off very almost all came off very easily under aslow easily under a slow stream stream of water. Tar was of water;however, not all. only very slightly sticky, Tar was stuck to the insidebut not as bad as of the cell, but it also came untreated tar. Fluid wasoff under a stream of water. not contaminated. Tar Fluid was notcontaminated. was far less adhesive Tar was far less adhesive and easilydisposed of. and easily disposed of.

As set forth in the table above, the tar sands were treated with thestyrene copolymer with the tar becoming non-adhesive in nature. Some ofthe tar was loosely adhered to the steel rod but was only mechanicallypressed to the rod as it slid off very easily upon application of astream of water, revealing the tar's non-adhesive nature.

Example 5

In this example, two additional fluid samples were prepared by adding anacrylate copolymer to Base Fluid 3 in different quantities to determineits effect on well bore tar, as set forth in Table 7. The fluid samplesare designated Samples H and I in the table below. The acrylatecopolymer was obtained as a latex emulsion (approx. 45 wt % active) andused as received. Baracor 700™ corrosion inhibitor, available fromHalliburton Energy Services, Inc., was also added to the fluid samples,as indicated in the table below. Tar sands with approximately 80% sandsand 20% bitumen by weight were used for this test. A steel rod was usedto mimic the drill strings interaction with the tar sands. For eachtest, the tar sands were placed in a lab barrel together with therespective fluid sample and the steel rod. The system was then aged byrolling at approximately 77° F. (approx. 25° C.) for 16 hours in arolling cell. The mass of the steel rod was determined prior to testingwithout any accreted tar and after testing with accreted tar. The massof the rod was also measured after rinsing under a stream of water.These masses and the mass of the accreted tar for each sample arereported in the table below.

TABLE 7 Sample H I Base Fluid 3 (ml) 120 120 Styrene Latex 10 30Emulsion (lb/bbl) Baracor 700 ™ 6 6 Corrosion Inhibitor (lb/bbl) TarSands (lb/bbl) 85 85 Pre-Accretion 335.07 334.60 Test Rod Mass (g)Post-Accretion 336.40 343.42 Rod Mass (g) (335.07 after rinsing) (334.80after rinsing) Mass of accreted 1.33 8.82 tar (g) (0.0 after rinsing)(0.20 after rinsing) Observations Some tar was mechanically Tar wasmechanically pressed to the bar but came pressed to bar but came offextremely easily under off extremely easily a slow stream of water. Tarunder a slow stream was not sticky. Tar was of water. Tar was also foundsunken in only slightly sticky, but the fluid that was not far less sothan untreated sticky at all. Fluid was not samples. Fluid was notcontaminated. contaminated.

While compositions and methods are described in terms of “comprising,”“containing,” or “including” various components or steps, thecompositions and methods can also “consist essentially of” or “consistof” the various components and steps. Whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “about a to about b,”or, equivalently, “from approximately a to b,” or, equivalently, “fromapproximately a-b”) disclosed herein is to be understood to set forthevery number and range encompassed within the broader range of values.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. It is therefore evident that the particular illustrativeembodiments disclosed above may be altered or modified and all suchvariations are considered within the scope and spirit of the presentinvention.

What is claimed is:
 1. A method for treatment of well bore tarcomprising: contacting tar resident in a well bore with an aqueous-basedtreatment fluid comprising a tar stabilizing polymer comprising acopolymer of styrene co-monomers wherein the copolymer of styreneco-monomers comprises the styrene co-monomers in an amount in the rangeof about 99% to about 100% by weight, wherein the copolymer of styreneco-monomers is essentially free of acrylate and acrylic acid, andwherein the tar stabilizing polymer is dispersed in the aqueous-basedtreatment fluid as a latex emulsion or a powder; and allowing theaqueous-based treatment fluid to interact with the tar to at leastpartially reduce the tendency of the tar to adhere to a surface; andafter the aqueous-based treatment fluid has interacted with the tar, thetar is removed from the well bore by filtering the tar from theaqueous-based treatment fluid.
 2. The method of claim 1, furthercomprising dispersing at least a latex emulsion comprising the tarstabilizing polymer in an aqueous fluid to form the aqueous-basedtreatment fluid, and introducing the aqueous-based treatment fluid intothe well bore.
 3. The method of claim 1, further comprising dispersingthe tar stabilizing polymer as a powder in an aqueous fluid to form theaqueous-based treatment fluid; and introducing the aqueous-basedtreatment fluid into the well bore.
 4. The method of claim 1, whereinthe tar stabilizing polymer is present in the aqueous-based treatmentfluid in an amount of about 1% to about 70% by volume of theaqueous-based treatment fluid.
 5. The method of claim 1, wherein the tarstabilizing polymer is present in the aqueous-based treatment fluid inan amount of about 1% to about 10% by volume of the aqueous-basedtreatment fluid.
 6. The method of claim 1, wherein the aqueous-basedtreatment fluid further comprises a viscosifying agent selected from thegroup consisting of a colloidal agent, a clay, a polymer, guar gum, anemulsion-forming agent, diatomaceous earth, a biopolymer, a syntheticpolymer, chitosan, a starch, a gelatin, and any mixture thereof.
 7. Themethod of claim 1, wherein the aqueous-based treatment fluid furthercomprises at least one additive selected from the group consisting of asalt, a surfactant, a fluid-loss-control additive, a gas, nitrogen,carbon dioxide, a surface-modifying agent, a tackifying agent, a foamer,a corrosion inhibitor, a scale inhibitor, a catalyst, a clay-controlagent, a biocide, a friction reducer, an antifoam agent, a bridgingagent, a dispersant, a flocculant, hydrogen sulfide scavenger, carbondioxide scavenger, an oxygen scavenger, a lubricant, a viscosifier, abreaker, a weighting agent, barite, a relative-permeability modifier, aresin, a particulate material, a proppant particulate, a wetting agent,a coating-enhancement agent, and any combination thereof.
 8. The methodof claim 1, wherein the method further comprises circulating theaqueous-based treatment fluid past a drill bit to remove drill cuttingsfrom the drill bit.
 9. The method of claim 1, wherein the method furthercomprises introducing the aqueous-based treatment fluid into the wellbore as a pill for a spot treatment of the well bore tar.
 10. The methodof claim 1, further comprising monitoring the concentration of the tarstabilizing polymer in the aqueous-based treatment fluid.
 11. The methodof claim 1, wherein the tar stabilizing polymer is introduced into azone of the well bore comprising tar sands.
 12. The method of claim 1wherein the copolymer of styrene co-monomers is substituted with atleast one group selected from the group consisting of a chloro group, abromo group, a fluoro group, an alkyl group, an alkoxy group, an alkenylgroup, an alkynyl group, an aryl group, and substituted versionsthereof.
 13. A method for treatment of well bore tar comprising:contacting tar resident in a well bore with a treatment fluid comprisinga tar stabilizing polymer comprising at least one polymer selected fromthe group consisting of a styrene polymer, an acrylate polymer, astyrene-acrylate polymer, and any combination thereof; and allowing thetreatment fluid to interact with the tar to at least partially reducethe tendency of the tar to adhere to a surface; and after the treatmentfluid has interacted with the tar, the tar is removed from the well boreby filtering the tar from the treatment fluid.
 14. The method of claim13, wherein the tar is removed by passing the treatment fluid through ascreen or similar separation apparatus.
 15. The method of claim 13,wherein the treatment fluid comprises the styrene polymer, and whereinthe styrene copolymer comprises styrene in an amount in the range ofabout 90% to about 100% by weight.
 16. The method of claim 13, whereinthe treatment fluid comprises the acrylate polymer, and wherein theacrylate copolymer comprises acrylate in an amount in the range of about90% to about 100% by weight.
 17. The method of claim 13, wherein thetreatment fluid comprises the acrylate polymer, wherein the acrylatepolymer comprises a copolymer of acrylate co-monomers comprising two ormore units individually selected from the group consisting of -acrylate,-methacrylate, -ethylacrylate, -propylacrylate, -butylacrylate,-tert-butyl-acrylate, -n-hydroxyethyl methacrylate, -potassium acrylate,-pentabromobenzyl acrylate, -methyl methacrylate, -ethyl methacrylate,-n-nitrophenyl acrylate, -methyl 2-(acyloxymethyl)acrylate, -cyclohexylacrylate, -n-ethylhexyl acrylate, any derivative thereof, and anycombination thereof.
 18. The method of claim 13, wherein the treatmentfluid further comprises a viscosifying agent selected from the groupconsisting of a colloidal agent, a clay, a polymer, guar gum, anemulsion-forming agent, diatomaceous earth, a biopolymer, a syntheticpolymer, chitosan, a starch, a gelatin, and any mixture thereof.
 19. Themethod of claim 13, wherein the treatment fluid further comprises atleast one additive selected from the group consisting of a salt, asurfactant, a fluid-loss-control additive, a gas, nitrogen, carbondioxide, a surface-modifying agent, a tackifying agent, a foamer, acorrosion inhibitor, a scale inhibitor, a catalyst, a clay-controlagent, a biocide, a friction reducer, an antifoam agent, a bridgingagent, a dispersant, a flocculant, hydrogen sulfide scavenger, carbondioxide scavenger, an oxygen scavenger, a lubricant, a viscosifier, abreaker, a weighting agent, barite, a relative-permeability modifier, aresin, a particulate material, a proppant particulate, a wetting agent,a coating-enhancement agent, and any combination thereof.
 20. The methodof claim 13, wherein the method further comprises introducing thetreatment fluid into the well bore as a pill for a spot treatment of thewell bore tar.
 21. The method of claim 13, wherein the tar stabilizingpolymer is introduced into a zone of the well bore comprising tar sands.22. The method of claim 13, and wherein the method further comprisescirculating the treatment fluid past a drill bit to remove drillcuttings from the drill bit.
 23. A method for treatment of well bore tarcomprising: contacting tar resident in a well bore with an aqueous-basedtreatment fluid comprising a tar stabilizing polymer comprising at leastone polymer selected from the group consisting of (i) a non-ioniccopolymer of acrylate co-monomers, wherein the copolymer of acrylateco-monomers comprises the acrylate co-monomers in an amount of about 99%to about 100% by weight, and wherein the copolymer of acrylateco-monomers is essentially free of styrene, and (ii) a copolymer ofacrylic acid formed by polymerizing acrylic acid, wherein the tarstabilizing polymer is dispersed in the aqueous-based treatment fluid asa latex emulsion or a powder; and allowing the aqueous-based treatmentfluid to interact with the tar to at least partially reduce the tendencyof the tar to adhere to a surface; and after the aqueous-based treatmentfluid has interacted with the tar, the tar is removed from the well boreby filtering the tar from the aqueous-based treatment fluid.
 24. Themethod of claim 23, wherein the copolymer of acrylate co-monomerscomprises two or more units individually selected from the groupconsisting of -acrylate, -methacrylate, -ethyl acrylate,-propylacrylate, -butylacrylate, -tert-butyl-acrylate, -n-hydroxyethylmethacrylate, pentabromobenzyl acrylate, -methyl methacrylate, -ethylmethacrylate, -n-nitrophenyl acrylate, -methyl2-(acyloxymethyl)acrylate, -cyclohexyl acrylate, -n-ethylhexyl acrylate,any derivative thereof, and any combination thereof.
 25. The method ofclaim 23, further comprising dispersing at least a latex emulsioncomprising the tar stabilizing polymer in an aqueous fluid to form theaqueous-based treatment fluid, and introducing the aqueous-basedtreatment fluid into the well bore.
 26. The method of claim 23, furthercomprising dispersing the tar stabilizing polymer as a powder in anaqueous fluid to form the aqueous-based treatment fluid; and introducingthe aqueous-based treatment fluid into the well bore.
 27. The method ofclaim 23, wherein the tar stabilizing polymer is present in theaqueous-based treatment fluid in an amount of about 1% to about 70% byvolume of the aqueous-based treatment fluid.
 28. The method of claim 23,wherein the tar stabilizing polymer is present in the aqueous-basedtreatment fluid in an amount of about 1% to about 10% by volume of theaqueous-based treatment fluid.
 29. The method of claim 23, wherein theaqueous-based treatment fluid further comprises a viscosifying agentselected from the group consisting of a colloidal agent, a clay, apolymer, guar gum, an emulsion-foi ming agent, diatomaceous earth, abiopolymer, a synthetic polymer, chitosan, a starch, a gelatin, and anymixture thereof.
 30. The method of claim 23, wherein the aqueous-basedtreatment fluid further comprises at least one additive selected fromthe group consisting of a salt, a surfactant, a fluid-loss-controladditive, a gas, nitrogen, carbon dioxide, a surface-modifying agent, atackifying agent, a foamer, a corrosion inhibitor, a scale inhibitor, acatalyst, a clay-control agent, a biocide, a friction reducer, anantifoam agent, a bridging agent, a dispersant, a flocculant, hydrogensulfide scavenger, carbon dioxide scavenger, an oxygen scavenger, alubricant, a viscosifier, a breaker, a weighting agent, barite, arelative-permeability modifier, a resin, a particulate material, aproppant particulate, a wetting agent, a coating-enhancement agent, andany combination thereof.
 31. The method of claim 23, and wherein themethod further comprises circulating the aqueous-based treatment fluidpast a drill bit to remove drill cuttings from the drill bit.
 32. Themethod of claim 23, wherein the method further comprises introducing theaqueous-based treatment fluid into the well bore as a pill for a spottreatment of the well bore tar.
 33. The method of claim 23, furthercomprising monitoring the concentration of the tar stabilizing polymerin the aqueous-based treatment fluid.
 34. The method of claim 23,wherein the tar stabilizing polymer is introduced into a zone of thewell bore comprising tar sands.
 35. The method of claim 23 wherein thecopolymer of acrylate co-monomers is substituted with at least one groupselected from the group consisting a chloro group, a bromo group, afluoro group, an alkyl group, an alkoxy group, an alkenyl group, analkynyl group, an aryl group, and substituted versions thereof.